Seismec source, a marine surveying arrangement, a method of operating a marine seismic source, and a method of de-gosting seimic data

ABSTRACT

A staggered vertical marine seismic source contains upper and lower arrays ( 10, 11 ) of emitters of seismic energy (S 11,  S 12;  S 21,  S 22 ). The upper array ( 10 ) is horizontally displaced relative to the lower array ( 11 ). The source is used in a marine seismic surveying arrangement that has means for moving the source and at least one seismic receiver.  
     In use, the source is moved through the water in a direction parallel to the direction in which the two arrays are displaced. The arrays ( 10, 11 ) are fired sequentially, and the time delay between the firing of the first-fired array and firing of the second-fired array is chosen such that each seismic emitter in one array is fired at the same x- and y-co-ordinates as the corresponding emitter in the other array. The seismic wavefields generated by firing the two arrays are thus generated at the same x- and y-co-ordinates, but at different depths.  
     The seismic data recorded at the receiver(s) as a consequence of firing the first array can be used to de-ghost the seismic data acquired as a result of firing the second array or vice-versa, thereby eliminating or reducing the effect of source-side ghost reflections and reverberations.

[0001] The present invention relates to a seismic source, in particularto a source for use in marine seismic surveying. The present inventionalso relates to a marine seismic surveying arrangement including asource, to a method of operating the source and to a method ofde-ghosting marine seismic data.

[0002] The principle of marine seismic surveying is shown schematicallyin FIG. 1. Seismic energy emitted in a generally downwards directionfrom a source of seismic energy 1 is reflected by the sea bed 2 and bythe earth strata or geological structures beneath the sea bed, and isreceived by an array of seismic receivers 3 such as hydrophones.Analysis of the energy received at the receiving array 3 can provideinformation about the earth strata or geological structures beneath theseabed. In the marine seismic surveying arrangement shown in FIG. 1, thesource of seismic energy 1 is suspended from a survey vessel 4 and thearray of seismic receivers 3 is towed by the survey vessel 3.

[0003] One problem associated with conventional marine seismic surveyingis that of “ghost reflections”. Ghost reflections occur when upwardlytravelling seismic energy is reflected or scattered downwards at the seasurface. A related problem in marine seismic surveying is that of“reverberations”. Reverberations occur when seismic energy is reflectedbetween the sea surface and the sea-bed. The problems of ghostreflections and reverberations are explained in FIGS. 2(a) to 2(d).

[0004]FIG. 2(a) shows a “primary reflection”. Seismic energy is emitteddownwards by the source 1, is reflected by a geological feature belowthe sea bed, and the reflected signal is detected at the receiver 3. Ananalysis of the seismic signal generated by the primary reflectionprovides information about the geological feature responsible forreflecting the seismic energy. (In practice, refraction may occur at thesea-bed, but this has been omitted from FIGS. 2(a) to 2(d) for clarity.)

[0005]FIG. 2(b) shows a ghost reflection. Seismic energy that has beenemitted upwards by the source is reflected or scattered downwards by thesea surface. The seismic energy that is reflected or scattered downwardsmay then be incident on the target geological feature, undergoreflection, and be reflected to the receiver. Seismic energy thatfollows the path shown in FIG. 2(b) will have a different travel timefrom the source to the receiver than will energy that follows theprimary path of FIG. 2(a). Ghost reflections are an undesirable sourceof contamination of seismic data since they tend to obscure theinterpretation of data produced by the primary reflection.

[0006] FIGS. 2(c) and 2(d) show reverberations, in which seismic energyundergoes reflections between the sea-bed and the sea-surface.Reverberations can occur in the case of seismic energy emitted in anup-going direction by the source (FIG. 2(c)) and also in the case ofseismic energy emitted in a down-going direction by the source (FIG.2(d)). As is the case for ghost reflections, reverberations are anundesirable source of contamination of seismic data, since they obscurethe interpretation of the primary reflection from the earth's interior.

[0007] FIGS. 2(b), 2(c) and 2(d) show source-side ghost reflections andreverberations—that is, ghost reflections and reverberations that occurbefore the seismic energy is reflected by the target geologicalstructure. (Indeed it will be noted that the path of seismic energyshown in FIG. 2(d) does not involve a reflection by the targetgeological structure.) Ghost reflections and reverberations can alsooccur after the seismic energy has been reflected from the targetgeological structure, and these are known as receiver-side ghostreflections or reverberations.

[0008] A number of schemes for minimising the effect of ghostreflections and reverberations on seismic data have been proposed. Formost survey arrangements, the attenuation of ghost reflections andreverberations is equivalent to separating the up-going and down-goingseismic wave fields.

[0009] F. J. Barr and J. J. Saunders have proposed, in a paper presentedat the 59th SEG Meeting (1989), a method of attenuating ghostreflections and reverberations by recording the reflected seismic signalusing two different types of seismic receivers, namely using bothhydrophones and geophones. The up-going wave field is recorded by thehydrophone and the geophone with the same polarity, while the down-goingwave field is recorded by the hydrophone and the geophone with oppositepolarities. The difference between the signal recorded by the hydrophoneand the signal recorded by the geophone allows the up-going wavefield tobe separated from the down-going wavefield.

[0010] An alternative method for attenuating ghost reflections andreverberations is to use two receivers located at different depths. Thismethod is based on the principle that waves travelling in differentdirections will have spatial derivatives of different signs, so thatcomparing the signal obtained at one receiver with the signal obtainedby the other receiver will allow the up-going wavefield to be separatedfrom the down-going wavefield.

[0011] These prior art methods separate the up-going and down-going wavefields at the receiver location. That is, they attempt to remove theghost reflections and reverberations that arise after the seismic energyhas been reflected by the target geological structure. This is known asreceiver-side deghosting. These prior art methods do not, however,address the problem of the ghost reflections and reverberations thatoccur before the seismic energy is reflected by the target geologicalstructure.

[0012] A first aspect of the present invention provides a marine seismicsource comprising: a first array of N emitters of seismic energy, whereN is an integer greater than 1; and a second array of N emitters ofseismic energy; wherein, in use, the first array is disposed at a firstdepth and the second array is disposed at a second depth greater thanthe first depth, and the j^(th) emitter of the first array (j=1, 2 . . .N) is displaced by a non-zero horizontal distance d_(H) from the j^(th)emitter of the second array along a first direction; and the jth emitterof the first array and the jth emitter of the second array both lie in avertical plane parallel to the first direction.

[0013] The use of two arrays of emitters of seismic energy at differentdepths allows the up-going and down-going seismic wavefields to beseparated from one another, as will be described below. The effect ofsource-side ghost reflections and reverberations on the seismic data canbe reduced or eliminated.

[0014] A second aspect of the present invention provides a marineseismic surveying arrangement comprising a marine seismic receiver; anda seismic source as defined above; means for moving the seismic source;and one or more seismic receivers.

[0015] A third aspect of the present invention provides a method ofoperating a marine seismic source as defined above, the methodcomprising the steps of: moving the seismic source at a speed v alongthe first direction; firing one of the first and second arrays ofemitters of seismic energy; and firing the other of the first and secondarrays of emitters of seismic energy after a time d_(H)/v. The timedelay of d_(H)/v between the firings of the two arrays of seismicsources ensures that each emitter of one array is fired at the samepoint in the x- and y-directions as the corresponding emitter of theother array, but at different depths. This allows the seismic datagenerated by one of the arrays to be used to de-ghost the seismic datagenerated by the other of the arrays.

[0016] A fourth aspect of the present invention provides a method ofprocessing marine seismic data comprising the steps of: firing a firstemitter of seismic energy at a point in a fluid medium having components(x₁, y₁, z₁), and detecting the resultant first seismic data at areceiver array; firing a second emitter of seismic energy at a point inthe fluid medium having components (x₁, y₁, z₂), where z₁≠z₂, anddetecting the resultant second seismic data at the receiver array; andusing the second seismic data to reduce the effects of source-sidereflections and/or scattering at the sea surface on the first seismicdata.

[0017] Preferred features of the invention are set out in the dependentclaims.

[0018] Preferred embodiments of the present invention will now bedescribed by way of illustrative examples with reference to theaccompanying figures, in which:

[0019]FIG. 1 is a schematic view of a typical marine seismic surveyingarrangement;

[0020] FIGS. 2(a) to 2(d) are schematic illustrations of the problems ofghost reflections and reverberations;

[0021]FIG. 3 is a schematic view of a vertical source array illustratingthe principles of the de-ghosting method of the present invention;

[0022]FIG. 4 is a schematic illustration of a vertical source arrayaccording to an embodiment of the present invention;

[0023]FIG. 5 shows a typical seismic signal recorded by a receiver in amarine seismic surveying arrangement that contains a seismic sourceaccording to an embodiment of the present invention;

[0024]FIG. 6 shows the signal of FIG. 5 after processing to attenuatesource-side ghost reflections and reverberations;

[0025]FIG. 7 illustrates the average amplitude spectrum of the signal ofFIG. 5; and

[0026]FIG. 8 illustrates the average amplitude of the signal of FIG. 6.

[0027]FIG. 3 illustrates the general principle of the de-ghosting methodof the present invention. FIG. 3 shows a vertical source array thatconsists of two emitters of seismic energy S1 and S2 that have identicalemission characteristics to one another. The emitters are disposed inthe water at two different depths. The upper emitter S1 is disposedsubstantially vertically above the lower emitter S2.

[0028] The source array generates a seismic wavefield that has bothup-going and down-going components. The wavefield travelling upwardsgenerates source-side ghost reflections and up-going reverberations inthe water layer. The wavefield travelling downwards from the sourcearray generates the primary reflection and also generates down-goingreverberations.

[0029] Consider a hypothetical emitter of seismic energy S havingidentical emission characteristics to the emitters S1 and S2, placed atthe mid-point between the upper emitter S1 and the lower emitter S2.This emitter S would generate up-going and down-going source wavefieldsat a reference time t. The total wavefield S(t) emitted by thehypothetical emitter S is the sum of the up-going and down-going sourcewavefields, that is:

S(t)=u(t)+d(t)  (1)

[0030] In this equation, u(t) is the up-going source wavefield and d(t)is the down-going source wavefield emitted by the hypothetical emitterS.

[0031] The emitters S1 and S2 generate up-going and down-goingwavefields. These wavefields can be described, relative to time t, bythe following equations:

S ₁(t)=u(t−dt)+d(t+dt)  (2)

S ₂(t)=u(t+dt)+d(t−dt)  (3)

[0032] In these equations, S₁ is the wavefield emitted by the upperemitter S1 and S₂ is the wavefield emitted by the lower emitter S2. Thetime dt is the time that seismic energy would take to travel from theupper or lower emitter S1 or S2 to the position of the hypotheticalemitter S. Since the hypothetical emitter S is at the mid-point betweenthe upper emitter S1 and the lower emitter S2, the time dt is equal tohalf the time taken for seismic energy to travel between the upperemitter S₁ and the lower emitter S₂ or vice versa.

[0033] On the assumption that dt is small, the terms in equations (2)and (3) can be expanded using a first-order Taylor expansion, asfollows:

S ₁(t)=u(t)−u′(t)dt+d(t)+d′(t)dt  (4)

S ₂(t)=u(t)+u′(t)dt+d(t)−d′(t)dt  (5)

[0034] In equations (4) and (5), u′(t) and d′(t) are the timederivatives of u(t) and d(t)1, respectively.

[0035] The sum of the two source wavefields S₁ and S₂ and the differencebetween the two source wavefields S₁ and S₂ can be derived fromequations (4) and (5) as follows:

Sum=S ₁(t)+S ₂(t)=2u(t)+2d(t)  (6)

Dif=S ₂(t)−S ₁(t)=2u′(t)dt−2d′(t)dt  (7)

[0036] Integrating both sides of equation (7) with respect to time leadsto the following result:

Intdif=2u(t)dt−2d(t)dt  (8)

[0037] Equations (6) and (8) may now be combined, to eliminate u(t).This leads to the following expression for the down-going sourcewavefield d(t):

d(t)=(Sum−Intdif/dt)/4  (9)

[0038] Thus, by using a vertical source array that consists of twoemitters of seismic energy that have identical emission characteristics,with one emitter disposed above the other, it is possible to derive thedown-going source wavefield d(t) using equation (9) above. This allowsthe effect of the up-going wavefield u(t) to be eliminated when seismicdata acquired using the source is processed.

[0039] The principle of reciprocity is a fundamental principle of wavepropagation, and states that a signal is unaffected by interchanging thelocation and character of the sources and receivers. For example, if asurveying arrangement with an array of seismic sources at point A and areceiver at point B gives a certain signal at the receiver, then using areceiver array at point A and a single source at point B would lead tothe same signal, provided that the source array corresponds to thereceiver array. (By “corresponds”) it is meant that the source arraycontains the same number of sources as the receiver array has receivers,and that the sources in the source array are arranged in the samelocations relative to one another as the receivers in the receiverarray.)

[0040] One consequence of the principle of reciprocity is that thetheory described above with relation to equations (1) to (9) above couldbe used for wave field separation using two vertically separatedreceivers. This would provide a method of receiver-side de-ghosting,which would enable the up-going wave field at the receiver, whichcontains the primary reflection, to be separated from the down-goingwavefield caused by reflection or scattering at the sea surface.

[0041] The above discussion relates to a vertical source array thatcontains just two emitters, with one emitter being disposed above theother. However, the same principle can be applied to a source thatcomprises a first array of two or more emitters of seismic energydisposed above a second array of two or more emitters of seismic energy.It is, however, necessary for the first and second arrays of emitters tohave substantially identical emission characteristics to oneanother—that is, each emitter array must contain the same number ofemitters, and each emitter in one array must have identical emissioncharacteristics to the corresponding emitter in the other array.Furthermore, the relative arrangement and separation of the emitters inone array must be the same as the relative arrangement and separation ofthe emitters in the other array.

[0042] If the upper and lower emitters S1 and S2 were firedsimultaneously, a receiver would record the combination of the wavefieldgenerated by the upper emitter S1 and the wavefield generated by thelower emitter S2. It would therefore not be possible to apply thede-ghosting method outlined above, since the difference between the twowavefields would not be known. To apply the method using the seismicsource shown in FIG. 3, it would be necessary to maintain the sourcestationary in the water, and fire the two emitters one after the other.This would generate two distinct wavefields S₁, S₂ that could berecorded separately and processed according to equations (1) to (9).However, it would be inconvenient in practice to have to hold the sourcestationary in the water.

[0043] In principle, the two separate wavefields required for thede-ghosting method could also be obtained by using firing a singleemitter at one depth, altering the depth of the emitter, and firing theemitter again. However, this method would also be inconvenient to carryout.

[0044] In a preferred embodiment of the present invention, therefore, astaggered vertical source is used consisting of two emitters or of twoemitter arrays, with, in use, one emitter or emitter array beingdisposed at one depth and the other being disposed at a different depth.The two emitters, or two emitter arrays, are displaced horizontally withrespect to one another. In use, the source is moved through the water inthe direction along which the emitters, or emitter arrays, aredisplaced. There is a time delay between the firing of one of theemitters or emitter arrays and the firing of the other emitter oremitter array. The time delay between the firings and the speed ofmovement of the source are chosen such that, in the case of a sourcehaving just two emitters, the point at which the upper emitter is firedhas the same x- and y-co-ordinates as the point at which the loweremitter is fired. In the case of a source having two arrays of emitters,the time delay between firing one array and firing the other array ischosen so that the point at which an emitter in one array is fired hasthe same x- and y-co-ordinates as the point at which the correspondingemitter in the other array is fired, for all emitters in the array.Thus, the invention makes it straightforward to generate identicalseismic wavefields at different depths but at the same x- andy-co-ordinates. The seismic data generated by one wavefield can then beused to de-ghost the seismic data generated by the other wavefield,using equation (9) above.

[0045]FIG. 4 shows an embodiment of the invention in which the sourceincludes two arrays 10, 11 each having two emitters of seismic energyS11, S12; S21, S22. The four emitters S11, S12; S21, S22 havesubstantially identical emission characteristics to one another. Theseparation between the two emitters S11, S12 of the first array 10 issubstantially equal to the separation between the two emitters S21, S22of the second array. In this embodiment, one array 10 is disposed at adepth of four metres, whereas the other array 11 is disposed at a depthof 10 metres. The axis of each emitter array is preferably horizontal,so that each emitter S11, S12 of the first array 10 is at a depth of 4metres and each emitter S21, S22 of the second array 11 is at a depth of10 m. The source is intended to be moved through the water at a speed v,and this is most conveniently done by towing the source from a surveyvessel, as shown in FIG. 1.

[0046] In addition to being separated in the vertical direction(z-direction), the two arrays are also displaced in a horizontaldirection. The direction of displacement of the two arrays is thedirection in which the source is towed in use. The arrays are displacedby a horizontal distance d_(H). In FIG. 4, the direction in which thearrays are displaced, and in which the source is moved in use, is chosento be the x-direction for convenience of description.

[0047] The two arrays are not displaced in the direction perpendicularto the direction of movement of the source (in FIG. 4 this is they-direction and extends out of the plane of the paper). An emitter ofone array and the corresponding emitter of the other array are bothdisposed in a common vertical plane, that is parallel to the directionof movement of the source.

[0048] The difference in depth between the first and second emitterarrays should be chosen such that 1/dt<f_(max), where f_(max) is themaximum frequency in the seismic data. The time dt is determined by thedepth difference between the two emitter arrays and by the velocity ofseismic energy in water, which is a known quantity. The embodiment ofFIG. 4 is intended for use with a maximum frequency f_(max)≦90 Hz, and adepth difference of 6 m has been found to be acceptable in this case.

[0049] As noted above, the two emitter arrays of the source shown inFIG. 4 have a horizontal displacement, d_(H). The horizontaldisplacement is measured between an emitter of the array nearer thetowing vessel and the corresponding emitter of the array further fromthe towing vessel.

[0050] The marine seismic source shown in FIG. 4 can be used in a marineseismic surveying arrangement. In addition to the source, thearrangement would also comprise one or more seismic receivers, andmeans, such as a towing vessel, for moving the source through the water.The marine seismic surveying arrangement would also comprises controlmeans for firing the emitters, and recording means for recording seismicdata acquired by the receiver(s).

[0051] In a particularly preferred embodiment, the horizontaldisplacement between the two emitter arrays is substantially equal tothe shot point interval of the marine seismic surveying arrangement.Thus, for a seismic surveying arrangement that generates a shot pointinterval of, for example, 25 m, the horizontal displacement of theemitter arrays of the seismic source is preferably approximately 25 m.

[0052] In this embodiment, the emitter arrays are fired in a “flip-flop”sequence at equal intervals of, in this example, 25 m. That is to say,the emitters on the array nearer the towing vessel are fired initiallyand they may be fired consecutively, or simultaneously. After a timedelay that is equal to the time required for the towing vessel to travel25 m, the emitters of the array further from the boat are fired. Thisresults in two shot records generated at points having the samex-co-ordinate and the same y-co-ordinate, but at different depths.

[0053] In FIG. 4 the array at the shallower depth is shown as the arraynearer the towing vessel. The invention is not limited to this, however,and the array at the shallower depth could be the array further from thetowing vessel.

[0054] The signals generated at the receiver or receiver array as theresult of firing the first emitter array and subsequently firing thesecond emitter array are recorded in any conventional manner. Since, asexplained above, the signals were emitted by the two emitter arrays atthe same x- and y-co-ordinates but at different z-co-ordinates, theresults can be analysed using the theory outlined above with regard toequations (1) to (9). In particular, by calculating the sum of the twosignals and the integral with respect to time of the difference betweenthe two signals, it is possible to compute the down-going sourcewavefield using equation (9). Thus, the present invention enables theeffects of the up-going source wavefield to be removed from theprocessed seismic data. The effect of source-side ghost reflections andreverberations is thus eliminated, or at least significantly reduced.

[0055] Results obtained using a seismic source according to the presentinvention and the de-ghosting method of the present invention areillustrated in FIGS. 5-8. These figures relate to a survey carried outusing a source having two emitter arrays, each array having two marinevibrator arrays as the seismic emitters. The source was towed with thearrays at depths of 4 m and 10 m respectively, with a 25 m in linedisplacement (by “in-line displacement” is meant displacement along thetowing direction) between the two arrays. The average water depth was 52m. An ocean bottom cable (OBC) dual sensor cable, 10 km in length,disposed on the sea bed was used as the receiver. The two arrays ofmarine vibrators were fired in a flip-flop mode as described above.

[0056] The parameters of the survey arrangement are as follows:

[0057] Number of receiver stations: 204

[0058] Receiver interval: 25 m

[0059] Receiver depth: 52 m

[0060] Sweep bandwidth: 5-90 Hz

[0061] Fold: 90

[0062] The data recorded in the OBC sensors as a result of firing theemitter array at a depth of 10 m is shown in FIG. 5. This shows the dataafter preliminary processing operations. The emitter array at a depth of4 m generated another record (not shown) at the same x, y location.

[0063]FIG. 6 illustrates the data of FIG. 5 after processing, usingequation (9) and the data recorded using the emitter array at a depth of4 m, to remove the up-going wavefield. That is, FIG. 6 shows the data ofFIG. 5 after de-ghosting to remove the effect of source-side ghostevents and reverberations.

[0064]FIGS. 7 and 8 show the average amplitude spectra for the seismicdata of FIGS. 5 and 6 respectively. It will be seen that the resolutionand the signal-to-noise ratio have both been improved by de-ghostingprocess.

[0065] In the preferred embodiment described above, the seismic sourceconsists of two arrays each containing two marine vibrator units. Thepresent invention is not, however, limited to this precise arrangement.For example, each of the source arrays could contain more than twoemitters of seismic energy. Moreover the de-ghosting method of thepresent invention could in principle be applied if seismic data acquiredusing a single seismic emitter at one depth and seismic data acquiredusing an emitter having identical emission characteristics at adifferent depth (but at the same x- and y-co-ordinates) is available.

[0066] In the embodiment shown in FIG. 4, each receiver array is anin-line emitter array—that is, the emitters of each array are arrangedalong the axis of the array. The axis of each array is coincident withthe towing direction when the source is in use. The invention is not,however, limited to use with in-line emitter arrays.

[0067] Furthermore, the seismic source of the invention is not limitedto a source that contains marine vibrator units. The source could alsoconsist of arrays of other emitters of seismic energy such as, forexample, air guns.

1. A marine seismic source comprising: a first array of N emitters ofseismic energy, where N is an integer greater than one; and a secondarray of N emitters of seismic energy, wherein, in use, the first arrayis disposed at a first depth and the second array is disposed at asecond depth greater than the first depth, the j^(th) emitter of thefirst array (j=1, 2 . . . N) is displaced by a non-zero horizontaldistance d_(H) from the j^(th) emitter of the second array along a firstdirection, and the jth emitter of the first array and the jth emitter ofthe second array both lie in a vertical plane parallel to the firstdirection.
 2. A marine seismic source as claimed in claim 1 wherein theN emitters of the first array are arranged along the axis of the firstarray and the N emitters of the second array are arranged along the axisof the second array.
 3. A marine seismic source as claimed in claim 2wherein, in use, the first and second arrays are disposed such thattheir axes lie substantially in a common vertical plane.
 4. A seismicsource as claimed in claim 2 or 3 wherein, in use, the first and secondarrays are disposed such that the axis of the first array and the axisof the second array are each substantially horizontal.
 5. A seismicsource as claimed in any preceding claim wherein each of the first andsecond arrays of emitters of seismic energy comprises N airguns.
 6. Aseismic source as claimed in any of claims 1 to 5 wherein each of thefirst and second arrays emitters of emitters of seismic energy comprisesN marine vibrator units.
 7. A seismic source as claimed in any precedingclaim wherein the first and second depths are chosen such that the timetaken for seismic energy to travel from the first depth to the seconddepth is greater than twice the reciprocal of the maximum frequencyemitted, in use, by the seismic sources.
 8. A marine seismic sourcesubstantially as described hereinabove with reference to FIG. 4 of theaccompanying drawings.
 9. A marine seismic surveying arrangementcomprising a marine seismic source as defined in any preceding claim;means for moving the seismic source; and an array of one or more seismicreceivers.
 10. A marine seismic surveying arrangement as claimed inclaim 9 and further comprising control means for firing a selected oneof the first and second arrays of emitters of seismic energy.
 11. Amarine seismic surveying arrangement as claimed in claim 9 or 10 whereinthe horizontal displacement d_(H) between the j^(th) emitter of thefirst array and the j^(th) emitter of the second array is substantiallyequal to the shot point interval of the surveying arrangement.
 12. Amarine seismic surveying arrangement as claimed in claim 11 wherein theshot point interval of the surveying arrangement is approximately 25 m.13. A method of operating a marine seismic source as defined in any ofclaims 1 to 8, the method comprising the steps of: a) moving the seismicsource at a speed v along the first direction; b) firing one of thefirst and second arrays of emitters of seismic energy; and c) firing theother of the first and second arrays of emitters of seismic energy at atime d_(H)/v after step (b).
 14. A method as claimed in claim 13 whereinstep (b) comprises firing the first array.
 15. A method of processingmarine seismic data comprising the steps of: a) firing a first emitterof seismic energy at a point in a fluid medium having components (x₁,y₁, z₁), and detecting the resultant first seismic data at a receiverarray; b) firing a second emitter of seismic energy at a point in thefluid medium having components (x₁, y₁, z₂), where z₁≠z₂, and detectingthe resultant second seismic data at the receiver array; and c) usingone of the first second seismic data to reduce the effects ofsource-side reflection and/or scattering at the sea surface on the otherof the first and second seismic data.
 16. A method as claimed in claim15 wherein step (c) comprises calculating d(t)=(Sum−Intdif/dt)/4 whereSum is the sum of the first and second seismic data, Intdif is theintegral with respect to time of the difference between the first andsecond seismic data; and 2dt is the time for seismic energy to travelfrom the point (x₁, y₁, z₁) to the point (x₁, y₁, z₂).
 17. A method asclaimed in claim 15 or 16 wherein the first and second emitters ofseismic energy are comprised in a seismic source as claimed in any ofclaims 1 to 8.